In most oil wells, water enters the well and is recovered together with the oil. Furthermore, as the well ages the amount or cut of recovered water generally increases. As the world's oilfields mature, there is an increasing focus on the development of systems to manage/process large quantities of water co-produced with the hydrocarbons and methods to reduce water production without reducing hydrocarbon production. Typically, the co-production of large quantities of water reduces the ultimate recovery of hydrocarbons from a well, increases the cost and size of the equipment used to separate the water from the hydrocarbons and increases the operating costs associated with disposing of the water in an environmentally acceptable manner. Various other problems can be associated with the co-production of large quantities of water; these include an increased tendency for the formation of emulsions, increased sand production, accelerated corrosion and scale deposition in tubulars and surface equipment.
Multi-layered reservoirs present particular water-production problems for-hydrocarbon recovery. A multi-layered reservoir consists of a number of oil-producing zones through which the bore is driven. Problems occur where one or more layers in the formation are “watered out”, producing fluid with a high water/oil ratio at an excessive rate.
A water-producing or watered-out zone or layer is a part of the formation that produces fluid with a high water/oil ratio. The large amounts of water in such zones make it economically inefficient to recover any oil that may also be present in those zones. However, there may be oil-rich layers nearby from which it is desirable to recover oil.
Water coning is another problem. Coning occurs where the upper boundary of a water-rich zone is located close beneath the bottom of the bore hole. Water can be sucked up or “coned” from below into the bore, resulting in potentially large volumes of water being co-produced as oil is drawn from the zones above. It may be that the bottom perforations of the bore hole are too close to the oil-water contact.
A classification of the main water problem types was presented by Elphick and Seright in: Elphick J., Seright, R., A classification of water control problem types, Presentation at the PNEC 3rd International Conference on Reservoir Conformance, Profile Control, Water and Gas Shut off, Houston, Tex., USA 1997. For certain problem types and in situations where the source of the unwanted water production can be defined and where appropriate mechanical isolation methods can be implemented, the conventional “water shut off” approach has been to deliver a non-selective blocking fluid which will block the flow of water (and oil) from the target watered-out layer/zone into which it is placed. Typically, such fluids are delayed polymer gel formulations which evolve from an easily injectable low viscosity pre-gel polymer solution during placement to a rigid crosslinked polymer gel capable of resisting flow in the near wellbore environment.
Several different approaches have been pursued in the development of selective fluid treatments. Typically, a selective fluid treatment involves the injection of a fluid or sequence of fluids into the near wellbore region of a producer well such that the treatment enters both the target watered out zone(s) and non-target oil-rich zone(s). When the well is put back on production, the treatment selectively reduces the rate of water production without reducing the rate of oil production. Such a treatment is required for situations where a sufficient diagnosis of the source of the unwanted water is prohibitively expensive and/or the watered out layers/zones cannot be isolated due to high intervention costs or well geometry constraints.
One selective fluid approach, extensively researched in recent years, is the use of relative permeability modifiers (RPMs); these are sometimes termed disproportionate permeability reducers (DPMs). In general, RPMs are water-soluble polymers which, when applied as a polymer solution or crosslinked gel, selectively reduce water permeability more than they reduce oil permeability. The most widely used RPM polymers are polyacrylamide (PAM) and partially hydrolysed polyacrylamide (HPAM); PAM/HPAM materials with degree of hydrolysis ranging from 0 to 50% and molecular weight ranging from 100,000 to >10,000,000 g/mol have been employed. The mechanisms by which RPM polymer solutions and crosslinked gels achieve a disproportionate reduction in water permeability relative to oil permeability have been investigated in numerous laboratory studies. Typically, an RPM treatment based on a solution of HPAM without crosslinker and applied in a water-wet sandstone (Clashach sandstone 200-900 mD) results in a 2.4 fold decrease in water permeability (at residual oil saturation, Sor) compared to a 1.6 fold decrease in oil permeability (at irreducible water saturation, Swi).
U.S. Pat. No. 6,228,812 describes a family of copolymers consisting of a hydrophilic monomeric unit, e.g. the ammonium or alkali metal salt of acrylamidomethylpropane sulphonic acid (AMPS) and a “first anchoring” monomeric unit (5-15 wt %) consisting of N-vinylformamide, N-methylacetamide and/or N,N-diallylacetamide; the copolymers can also include a second anchoring unit such as dimethyldiallyl ammonium chloride and/or the ammonium or alkali metal salt of acrylic acid and a “filler” unit based on acrylamide and/or methylacrylamide. The “anchoring” units are designed to promote binding to pore-lining minerals (in particular, clays and feldspars) in the formation so that the polymer is more strongly retained during production. The idea is that after the polymer solution has been injected into the formation, the treatment is shut in to allow the amide-containing units to be hydrolysed to form amine anchoring groups. The data given in the examples indicate that the copolymers induce a significant selective reduction of water permeability relative to oil permeability when applied in Berea sandstone cores of initial brine permeability 1000 mD. The factors by which the water and oil permeabilities are reduced by the treatment are strongly influenced by the backflow rate. At low backflow rates, the factor by which the water permeability is reduced can be greater than 10 times the factor by which the oil permeability is reduced. At higher backflow rates, the water permeability (at Sor) is decreased by a factor 1.9-2.5 compared to a 1.0-1.1 fold decrease in oil permeability (at Swi); it is notable that the effect on the oil permeability is significantly lower than that reported for a typical non-crosslinked HPAM treatment.
U.S. Pat. No. 6,133,204 describes a selective treatment based on the use of a delayed polymer gel formulation which evolves to form a flow resistant crosslinked polymer gel in the watered out layer/zone but which will not form a crosslinked gel in the oil-rich layer/zone(s) due to its interaction with a gel-breaking/gel-inhibiting fluid. The latter is a one phase oil/solvent mixture in which is dissolved 2-10% carboxylic acid e.g. citric acid or lactic acid; the example given is a fluid containing 70% oil, 20.5% isopropanol and 4.5% citric acid. The gel-inhibiting fluid can be injected as a preflush, as a postflush or both; the invention relies on the preferential injection of the gel-inhibiting fluid into the oil-rich zones.
G.B. patent 2335428A describes gelling formulations formed by hydrophobically-modified polymers and their application in water control operations. This patent describes the concept of preventing crosslinking of the hydrophobically modified polymer when the fluid is in contact with hydrocarbon; thus, such selective formulations can be used to form a polymer gel in watered out layer/zone but not in the oil-rich layers/zones.
Selective fluids based on viscoelastic surfactants in combination with crosslinkable, preferably hydrophobically modified, water-soluble polymers and related delayed viscoelastic surfactant based gelling compositions are also known. The known methods include a process in which a plug of viscous fluid based on a viscoelastic surfactant is injected into the formation prior to a polymer-based fracturing treatment; during backflow, the production of formation water is selectively retarded by the viscous plug leading to a higher recovery of the fracturing fluid. The same patent also describes the use of viscoelastic surfactant based fluids to divert acidising formulations into hydrocarbon-rich zones. These and other selective processes based on viscoelastic surfactants are also described in U.S. patent application 20020023752.
U.S. Pat. No. 4,183,406 describes a selective fluid formulation based on a polymer solution consisting of a neutralized ionomeric polymer dissolved in a nonpolar organic liquid and a polar cosolvent. Upon mixing with water, the polar cosolvent in the polymer solution is taken up by the water and the polymer and nonpolar organic liquid components then form a gel; a typical formulation contains diesel oil, sulphonated ethylene-propylenediene terpolymer and methanol. A similar approach has also been proposed for use in non-aqueous fracturing fluids.
U.S. Pat. No. 5,735,349 describes a selective fluid formulation based on a dispersion of water swellable crosslinked polymer particles (0.05-1 micron in diameter) made by invert polymer emulsion or microemulsion processes. After the dispersion has been injected into the formation, contact by water during backflow causes the particles to swell many times their initial size thereby blocking flow; in contrast, it is claimed that the particles remain shrunken and non-blocking in the oil-rich zones.
U.S. Pat. No. 4,191,249 describes an oil-based selective fluid formulation which contains an oil-soluble thickening agent (e.g. polymethyl laurylate, polyalkyl styrene, polybutadiene, polyisobutylene or a di/trivalent metallic soap of a monocarboxylic acid with 14 or more carbon atoms) and a solid particulate water-soluble thickening agent (e.g. HPAM, cellulose derivative or natural gum). After injection, mixing with water during backflow causes the water-soluble thickening agent to inhibit flow whilst it is claimed that the treatment fluid is more easily removed from the oil-rich zones. Other oil-based selective fluid systems have been reported including the crude oil/emulsifier system described, forming a flow-resistant or blocking emulsion in the watered out layer/zone compared to a negligible permeability reduction in the oil-rich zones.
The application of oil-soluble, water-insoluble particles has been proposed for improving fluid loss control in drilling, completion, workover, fracturing and acidising fluids. For example, Fischer et al. in U.S. Pat. No. 3,979,304 And U.S. Pat. No. 3,979,305 proposed the use of a particulate homogeneous solid solution of (1) wax, (2) oil-soluble polyhydroxy higher fatty acid partial ester surfactant and (3) water-dispersible surfactant (e.g. polyethoxyethylene alkyl phenol, polyethylene glycol higher fatty acid ester, polyethoxyethylene tertiary fatty amine or polyethoxyethylene fatty amide condensate). The same investigators extended their proposal to include slowly oil-soluble water-insoluble particles in U.S. Pat. No. 3,989,632.
U.S. Pat. No. 4,525,285 describes an oil-based drilling fluid comprising oil, water, weighting agent, emulsifying agent and a powdered “seepage loss reducer”. The latter component is an amorphous silicate (with molar ratio SiO2/M2O in the range 1.5-3.3 where M is sodium and/or potassium) and/or an ammonium soap of a fatty acid having about 12 to about 22 carbon atoms (the examples mention the use of ammonium oleate and ammonium laurate; the preferred fatty acids are oleic acid, ricinoleic acid and palmitoleic acid). The idea is that the “seepage loss reducer” will react with polyvalent cations (e.g. calcium) in the formation to form a precipitate seal adjacent to the wellbore.
U.S. Pat. No. 4,352,396 describes a selective treatment fluid based on a resin emulsion which, after placement, demulsifies to form coalescent oil-soluble water-insoluble resin droplets. The resin emulsion comprises an aqueous continuous phase, a resinous disperse phase and emulsifier(s); also included is an ester compound which after placement degrades to induce/promote demulsification. The oil-soluble water-insoluble resin droplets coalesce to form liquid droplets which can resist flow in the watered out layer/zone(s). In this scenario, the resin has a softening temperature which is lower than the temperature of the formation. A typical example comprises a 50% emulsion of petroleum aliphatic particles stabilized with a soap of wood rosin as the emulsifier. The preferred ester is ethyl monochloroacetate; the acid formed by degrading the ester must have a sufficient strength to initiate demulsification. When the emulsion is injected into oil-rich zones, there is no associated plugging as the resin droplets are readily soluble in the oil phase.
U.S. Pat. No. 6,419,017 describes a method of preventing gas breakthrough in an oil well which involves injecting the following sequence of aqueous solutions: (i) a solution of alkaline earth salt (e.g. calcium chloride or magnesium chloride), (ii) a spacer solution of alkali metal salt (e.g. 2 wt % KCl) and (iii) an aqueous dispersion of oil soluble fatty acid(s), CH3(CH2)nCOOH where n is typically between 12 and 24 and, preferably, the fatty acid(s) is unsaturated. The patent mentions the following fatty acids: palmitic, stearic, oleic, linoleic, linolenic, eleostearic, licanic, ricinoleic, palmitoleic, petroselenic, vaccenic and erucic. The third pumped aqueous dispersion of oil-soluble fatty acid(s) may also contain isopropyl alcohol, ammonium hydroxide and so-called tall oils or rosin. On backflow, the divalent cations, Ca++ and/or Mg++ in the first pumped solution react with the carboxylate groups in the third pumped dispersion to precipitate a material which is oil-soluble. This fatty acid resin precipitate is insoluble in water or gas but it gradually dissolves in oil to allow oil to be produced from the oil-rich zones.
The use of oil-soluble tracer solutions based on a non-polar solvent in which is dissolved the gadolinium salt of an α-branched carboxylic acid has been described in U.S. Pat. No. 6,001,280 and the International patent application WO 02/11873/A1. Such tracer solutions are used in methods to measure the flow velocity of a hydrocarbon phase in a multiphase flow. α-branched carboxylic acids which are soluble in both organic and aqueous fluids have also found oilfield application in viscoelastic surfactant gels.
GB 2348447 and EP 1041242 describe oil-soluble crystalline additives for water-based well-bore fluids. Examples of the additives used are camphor, lanolin and IS-endo-Borneol. The additive forms a “filtercake” at the boundary between the well-bore and the formation. When hydrocarbons flow back from the formation, the filtercake is partially dissolved.
A number of methods to reduce water production are based on precipitates generated in the formation from aqueous and non-aqueous treatment fluids. Among those the most relevant to the invention are the following.
U.S. Pat. No. 5,346,013 describes a method for reducing the influxes of water of a deposit using a non-aqueous solution of a hydrophobe water-insoluble polymer which precipitates in the presence of the connate water of the deposit.
U.S. Pat. No. 3,866,685 describes methods and compositions for selectively blocking the water rich strata of subterranean formations including the injection into the formation of a water-soluble, oil-insoluble soap or ester. The water-soluble and oil-insoluble soaps include water-soluble derivatives of abietic acid.
U.S. Pat. No. 3,859,107 describes a composition for stimulating production including an aqueous solution of a polar solvent having dissolved in the solution rosin soap and fatty acid soap. The composition reacts with the connate brine to produce a precipitate that blocks the brine bearing passages.
U.S. Pat. No. 3,695,356 describes a composition for plugging off sources of water by injecting solutions of chemicals which preciptate at a controlled rate, for example aqueous solutions of isocyanuric salts which hydrolyze.
Another method of sealing porous formation is described in the U.S. Pat. No. 2,858,892. The method includes the use of water-soluble salts of water-insoluble acids sauch as rosin soaps and abietic acid with delayed precipitation.
Another method for shutting off water entering wells is described to in the U.S. Pat. No. 2,842,206. The patent teaches dissolving oil soluble, water insoluble material at 40% to 60% by weight in alcohol and injecting the solution into the water producing formation. The material is a rosin polymer in a water miscible solvent. The solvent is specifically characterized as being miscible in all proportions with water to remove any limitation on the degree of precipitation of the rosin polymer. The required high content of treatment material makes this method economically unattractive.